The present invention relates to methods and compositions for treating subterranean well formations, and more specifically, to improved clean-up compositions comprising carboxylic acids and oxidizers, and methods for reducing the viscosity of viscosified treatment fluids.
A variety of viscosified treatment fluids are used in subterranean applications, such as drilling fluids, fracturing fluids, and gravel pack fluids. As used herein, the term “treatment fluid” refers generally to any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose. The term “treatment fluid” does not imply any particular action by the fluid or any component thereof. A “viscosified treatment fluid” is a treatment fluid with some degree of viscosity usually imparted by a gelling agent or a viscoelastic surfactant. Oftentimes, after the viscosified treatment fluid has performed its desired task, it may be desirable to reduce its viscosity so that the treatment fluid can be recovered from the formation and/or particulate matter may be dropped out of the treatment fluid at a desired location within the formation. Reducing the viscosity of a viscosified treatment fluid is often referred to as “breaking” the fluid.
Well stimulation treatments, such as fracturing treatments, commonly employ viscosified treatment fluids. Fracturing generally involves pumping a viscous fracturing fluid into a subterranean formation with sufficient hydraulic pressure to create one or more cracks or “fractures.” The fracturing fluid generally has a viscosity that is sufficient to suspend proppant particles and to place the proppant particles in fractures, inter alia, to maintain the integrity of those fractures once the hydraulic pressure is released. Once at least one fracture is created and the proppant is substantially in place, the viscosity of the fracturing fluid usually is reduced, and the fluid is recovered from the formation.
Similarly, sand control operations, such as gravel packing, use viscosified treatment fluids, often referred to as gravel pack fluids. Gravel pack fluids usually are used to suspend gravel particles for delivery to a desired area in a well bore, e.g., near unconsolidated or weakly consolidated formation particulates. One common type of gravel packing operation involves placing a gravel pack screen in the well bore and packing the annulus between the screen and the well bore with gravel of a specific size designed to prevent the passage of formation sand. When installing the gravel pack, oftentimes the gravel is carried to the formation in the form of a slurry by mixing the gravel with a transport fluid. The gravel, inter alia, acts to prevent the particulates from occluding the screen or migrating with the produced fluids, and the screen, inter alia, acts to prevent the gravel from entering the production tubing. Once the gravel pack is substantially in place, the viscosity of the gravel pack fluid often is reduced to allow it to be recovered from the well bore.
For some viscosified treatment fluids their viscosity may be related to pH. Thus, viscosity-reducing agents that reduce the pH of the treatment fluid may be added to reduce the viscosity of the fluid. Internal breakers, such as enzymes, oxidizers, acids, or temperature-activated viscosity reducers, also are used to reduce the viscosity of viscosified treatment fluids. Unfortunately, these traditional breakers may result in an incomplete or premature viscosity reduction. Premature viscosity reduction is undesirable as it may lead to, inter alia, the particulates settling out of the fluid in an undesirable location and/or at an undesirable time. Moreover, conventional non-delayed breakers begin to reduce the viscosity of the viscosified fluid upon addition and continue to reduce the fluid's viscosity with time until the fluid is completely broken or until the breaker is expended. Since the breaking activity begins immediately, it is common practice to start with excess viscosifier to offset the point at which the viscosity falls below an acceptable level. Using excess viscosifier is not only an added expense, it also may lead to excessive friction pressure during treatment placement.
As an alternative to using traditional breakers, breaking a viscosified treatment fluid also may be accomplished using just time and/or temperature. The viscosity of most treatment fluids will reduce naturally if given enough time and at a sufficient temperature. However, such methods generally are not practical as it is highly desirable to return the well back to production as quickly as possible as opposed to waiting for the viscosity of a treatment fluid to naturally decrease over time.
As an alternative to linear polymeric gels for pills, cross-linked gels often are used. Cross linking the gelling agent polymer is thought to create a gel structure that is better able to support solids and possibly, e.g., provide fluid-loss control. Further, cross-linked pills are thought to invade the formation face to a lesser extent to be desirably effective. To crosslink these gelling agents, a suitable cross linking agent that comprises polyvalent metal ions is often used. Complexes of aluminum, titanium, boron, and zirconium are common examples.
A disadvantage associated with conventional cross-linked gelling agents is that the resultant gel residue is often difficult to remove from the subterranean formation once the treatment has been completed. For example, in fracturing treatments, the cross-linked gels used are thought to be difficult to completely clean up with conventional breakers, such as oxidizers or enzymes. Similarly, the gel residue can be difficult and time-consuming to remove from the subterranean formation. The gel residue, at some point in the completion operation, usually should be removed to restore the formation's permeability, preferably to at least its original level. If the formation permeability is not restored to its original level, production levels can be significantly reduced. This gel residue often requires long cleanup periods. Moreover, an effective cleanup usually requires fluid circulation to provide high driving force, which is thought to allow diffusion to take place to help dissolve the concentrated buildup of the gel residue. Such fluid circulation, however, may not be feasible. Additionally, in lower temperature wells (i.e., those below about 80° F.), it is often difficult to find an internal breaker for the viscosified treatment fluids that will break the gel residue effectively. The term “break” (and its derivatives) as used herein refers to a reduction in the viscosity of the viscosified treatment fluid, e.g., by the breaking or reversing of the crosslinks between polymer molecules or some reduction of the size of the gelling agent polymers. No particular mechanism is implied by the term. Another conventional method of cleaning up gel residue is to add a spot of a strong acid (e.g., 10% to 15% hydrochloric acid) with coiled tubing, which is expensive and can result in hazardous conditions.
Another problem presented by today's crosslinked gelling agent systems with respect to clean-up is that the high temperature of the formations (e.g., bottom hole temperatures of about 200° F. or greater) often require cross linking agents that are more permanent, and thus harder to break. Examples include transition metal cross linking agents. These more permanent cross linking agents can make cleanup of the resulting gel residue more difficult.
The problem of breaking gels (whether crosslinked or not) is also a problem at many of the new lower temperature wells (e.g., bottom hole temperatures of about 130° F. or lower). Catalysis of the breakers (i.e., referred to herein a breaker activators) is often employed to improve breaking of the fluid but finding a suitable formulation that meets all performance criteria is often a challenge.